西南能源 (SWN) 2013 Q3 法說會逐字稿

Greetings. Welcome to the Southwestern Energy third-quarter 2013 earnings conference call. At this time all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation.

(Operator Instructions)

As a reminder this conference is being recorded. It is now my pleasure to introduce your host Steve Mueller, Chief Executive Officer for Southwestern Energy. Thank you, sir. You may begin.

Thank you. Good morning and thank you for joining us. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Senior VP of Corporate Development; and Brad Sylvester, our VP of Investors Relations. If you have not received a copy of yesterday's press release regarding our third-quarter 2013 results, you can find a copy of all of this on our website at www.swn.com.

Also I'd like to point out that many of the comments during this teleconference are forward looking statements and involve risk and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and the forward looking statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin, we posted record results in the third quarter. Not only did we set new records for production, EBITDA, and cash flow, but each of our operating teams achieved new milestones as well. Bill and Craig will recap how we achieved these strong results. Before we do that I'd like to address a few questions that you might have. First question, did SWN curtail any gas from Marcellus in the third quarter? And do we expect any curtailments in the fourth quarter? The answer to both of those are no.

We put our system in place to purchase firm and follow that firm curve just like we have in the Fayetteville. It's worked well in the Fayetteville and worked well for us in the third quarter in the Marcellus. We will talk more about that take away later in the call. One thing I do want to note though is on the marketing side we had a little bit of extra firm earning quarter and we were actually able to buy some gas at less than $1 and sell it at $3.60 at another point. I don't know if we'll be able to do that in if future. But it just shows you that having firm at several points is valuable.

Second question that you might have out there. Certainly the numbers aren't growing perfectly upwards. And sometimes those are 30-day rates, sometimes those are 60-day rates, sometimes those are the fourth-quarter guidance. Does this mean we should expect bad things in the fourth quarter, or next year, or three years or five years down the road? We'll be happy later onto talk about all the details you want as far as the numbers and which way they're trending and how important those numbers are. You'll see a lot of the answers are similar ones you've seen in the past, where we're in slightly different areas or we've got slightly different pressures going against other kinds of line pressures. The key question is should we expect something bad in the future? Your expectations should be the same as ours. Our expectations are high and we think things will be great in the future.

Third, Brown Dense. I really struggled with how to describe where we are on the Brown Dense. We drilled our first commercial well and plan to drill three more wells by the end of the year. That's where I start to struggle. What do I tell you? We're almost ready to declare commercial. We're getting close to knowing the key things needed to make it commercial. The text that Brad prepared and all the Senior Management agreed to says not ready to call the economic but encouraged.

For now I'd like to tell you where I'm at on it. Where I'm at today is that I believe we have a new discovery and our task for our Company is to figure out how big. Today if you asked me the size, maybe a township, could be much, much bigger when it's all done. And our second task once we figure out how big is how fast we can get it into the pipeline and get it to the bottom line. Those are the three questions I want to address to begin with.

Now I'll turn it over to Bill for more details on our operations and then to Craig for a recap of our financial results.

Thank you, Steve. Good morning, everyone.

To echo Steve's comments we had a terrific quarter, which was again driven by our proven industry leading operating capability, and really underpinned by our curiosity and constant focus on delivering more to our shareholders. Our Marcellus properties continued on our planned path of significant growth by reaching a gross operating production rate of over 600 million cubic feet of gas per day in August. We also added firm transportation, as Steve mentioned, enabling this growth to continue. In our Fayetteville, our focus on constantly improving the value of this huge asset continues to produce results as we place two of the highest rate wells ever drilled and completed on production during the quarter with IP rates near 10 million cubic feet per day of gas. In addition we continued testing the upper Fayetteville formation, and in October, we brought on two wells, producing at the highest rates we've seen to date from upper Fayetteville wells.

As Steve mentioned briefly in our Brown Dense play we have drilled and completed our first economic well, the Sharp vertical well located in Union Parish, Louisiana. This well reached a peak rate of 600 barrels a day of 52 API gravity oil, and 1.3 million cubic feet per day of 1,240 BTU gas. After 88 days on production this well continues to flow at 530 barrels of oil per day, and 1.1 million cubic feet per day on a 16/64-inch choke. We will speak more about this in our plans in a few minutes.

When I say overall, we completed the third quarter with a 19% growth in our total production and have made a third upward revision to our production guidance for the year. This is testimony to the creativity, hard work, dedication, and focus of all of our teams on delivering more value in all they do.

Let me begin in the Marcellus where we placed 22 wells on production during the quarter, which led to net production that was almost 200% greater than compared to a year ago, rising to approximately 45 billion cubic feet per day of gas, up from 15 billion cubic feet per day of gas in the third quarter of 2012. We continue to be pleased with our results as we delineate our acreage in Susquehanna County. We placed 12 wells on production in this area during the third quarter, and gross operating production was 267 million cubic feet per day at September 30 from a total of 61 is wells, up from 184 million cubic feet per of day of gas at July 1. We added another phase of compression in Northern Susquehanna County last week, which now allows over two-thirds of our wells in that area to produce at higher rates. Additional compression is planned to be in service in the area in the first quarter of 2014. We are planning on testing more of the acreage in the county as you move north and east towards the New York border, which will begin in 2014. In December we will drill our first well in Sullivan County on the acreage we acquired earlier this year and we'll be drilling in Wyoming and Tioga counties in early 2014.

On the gathering side, our midstream gathering Company was gathering 344 million cubic feet per day from 89 miles of owned gathering lines across all of our Marcellus acreage, out of a total of 611 million cubic feet of gas per day being produced at September 30. It's well-known that basis differentials in the Marcellus area widened dramatically at certain points beginning in June during the entire quarter. As Steve mentioned, our gas marketing team did an outstanding job of getting the majority of our gas to high value sales points with better prices during the quarter. Our ability to move our Marcellus gas to better priced and more liquid markets is built on our strategy of securing firm transportation capacity to move our gas out of the area. In fact, we've just executed an agreement to secure additional firm transportation capacity on Millennium subject to completing a new interconnect project beginning in November of 2014 for an additional 150 million cubic feet of gas per day. This increases our total firm capacity out of the basin to approximately 872 million cubic feet per day by the end of 2014 and over 1 billion cubic feet of gas per day by the end of 2015. We won't stop there. We will keep you updated as we're able to obtain more firm transportation capacity in order to move our gas to the best-priced areas in the country.

We expect to have another year of very strong results in Marcellus in 2014, and we'll be giving you more information on our plans for Marcellus in our capital program update in December. In the Fayetteville shale we placed 89 horizontal wells on production in the third quarter at a record initial production rate of 500 million cubic feet of gas per day. And this rate was bolstered by an extremely good September where placed on production 31 wells at an average initial rate of 5.4 million cubic feet of gas per day. Results during the quarter included two of the strongest wells we've drilled and completed since we announced the play in 2004, the Sneed and the Ledbetter wells, which achieved peak 24 hour production rates of 10.1 million and 9.2 million cubic feet of gas per day respectively.

As I mentioned, earlier, we also had encouraging results from a couple of upper Fayetteville tests placed on production in early October, that achieved a peak 24 hour production rate of 6.6 million and 6.7 million cubic feet per day of gas respectively. We're continuing to evaluate this reservoir and believe it could provide material additional gas resource to capture over time. Not only did we put online some of the largest wells in the play during the quarter, which contributed to our highest ever quarterly IP rate in the Fayetteville, but we're also seeing tangible benefits from changes we're making in our completion and flow back procedures in certain parts of the play that are enhancing early well productivity. We began a procedure of resting wells for a short period of time, only 10 to 20 days, before we placed them on production. Our results to date have shown that by resting these wells before we place them on production, we're seeing lower produced water volumes, and therefore lower water handling costs, and higher initial gas volumes in some areas. We've completed a total of 55 tests to date and plan to have around additional 20 wells to place on production in the fourth quarter.

It now is a standard procedure in two pilots, our Pike and Sturgeon areas, where historically wells are relatively deeper and exhibited higher initial water production rates. Those areas have shown the greatest benefit to date. Our completed well costs were $2.6 million in the quarter, up from $2.3 million in the second quarter due to longer lateral's and deeper average vertical depths. Through the first 9 months our average well cost has been $2.3 million per well. Our vertically integrated services continue to be a significant benefit in lowering our well costs and that has resulted in an estimated $380,000 per well savings so far in 2013.

Let me move onto new ventures where we remain encouraged, I'll change that to excited, about the work that's going on in the Brown Dense exploration program, where we're seeing it pay off and believe that the potential value creation from this project could be substantial for us over time. As I mentioned briefly, we have recently drilled and completed our first economic well, the Sharp, which is a vertical well located in Union Parish, Louisiana. This well was completed this three stages with resin coated proppant and cross-link gel, and accessed the entire Brown Dense interval, which is about 450 feet thick in this well. The Sharp well has since shown a flattening production profile, which is promising. We're encouraged about this result and will continue to watch the shape of its production profile over time.

Our next vertical well, the Hollis, was completed with three stages, and again accessed the entire Brown Dense interval. The well commenced flow back last week and it is still unloading. We will keep you abreast of that in the future. Our Man well located in Columbia County, Arkansas reached a total depth last week and we expect to complete this well with three to four stages in late November. We also spud our Plum Creek vertical test well in Union Parish last week, with a target vertical depth of 9,500 feet.

As we capture and understand the learnings from various technical studies underway and our recent wells in the near term, we will drill a series of vertical wells and apply what we're learning from these vertical wells to see if we can unlock more contactable reservoir volume with horizontal wells in the future. We continue to test not only different completion techniques but also different theories in each of these wells. While I realize the results we are reporting to you are only on a few wells with short production histories, we're excited about the potential in the Brown Dense. We're learning more with each well we drill and making solid progress on best practices for drilling and completing these wells. We believe we've moved our understanding and our performance in the play forward, and we'll keep working to unlock this resource and further improve our results.

In the Denver-Julesburg basin in Colorado, our oil play there, the Staner well, which included a 3,400 foot lateral with ten stages completed, was placed on production in July and reached a peak rate of 146 barrels of oil per day. We will continue to test the Marmaton and Atoka with additional wells to be spud in the first quarter. In Paradox basin in Utah, we will continue to test our acreage with additional wells to be drilled in 2014, and we continue to lease acreage in this area and we'll update everyone on our activity by the next quarter.

To close, I'm very proud of the results we've had in the third quarter, but more importantly I'm proud of the hard work and commitment that all of our teams have exhibited throughout the year. We know that there's more work to be done to keep driving our costs down while increasing the innovation and the successful execution of every aspect of the projects we have before us. We remain really excited about our new ventures projects and also are focusing on more exploration ideas to initiate next year. We have much more to look forward to as we enter 2014.

I will now turn it over to Craig Owen who will discuss our financial results.

Thank you Bill. Good morning, everyone.

Our results were excellent driven by higher production volumes and higher gas prices. Excluding non-cash items we reported a record net income of approximately $180 million or $0.51 per share in the third quarter, compared to net income of $132 million or $0.38 per share last year. Cash flow from operations before changes in operating assets and liabilities was a record $527 million, up 7% sequentially, and up 26% compared to the third quarter of 2012, and also within $15 million of our capital investments for the quarter. Operating income for our exploration and production segment was $223 million, up 51% compared to $148 million in the third quarter of 2012.

We realized an average gas price of $3.60 per Mcf during the third quarter, compared to $3.41 per Mcf last year. And have 84 Bcf of our remaining 2013 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.68 per MMBtu. We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu. As for field differentials, we currently have projected approximately 74 Bcf of our remaining 2013 projected natural gas production from the potential widening base differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately $0.06 per Mcf. This includes approximately 20 Bcf of our expected Marcellus volumes at $0.08 per Mcf. If total, we expect a $0.55 discount to NYMEX for the fourth quarter of 2013, which includes transportation and fuel charges.

Our cash operating cost of approximately $1.25 per Mcfe in the third quarter continued to be a competitive advantage for us. Lease operating expenses for our E&P segment were $0.87 per Mcfe in the third quarter, up from $0.79 per Mcfe last year, primarily due to higher third-party compression and gathering costs in the Marcellus shale, partially offset by lower salt water disposal costs in the Fayetteville shale. Our G&A expenses were $0.24 per Mcfe, up from $0.21 per Mcfe a year ago due to higher personal costs. Taxes other than income taxes were at $0.9 per Mcfe for both periods. And our full cost pool amortization rate fell to $1.07 per Mcfe compared to $1.30 per Mcfe last year.

Operating income for our midstream services segment for the quarter was up 15% to approximately $87 million compared to last year. As of September 30, our debt to total book capitalization ratio was 35%, which is flat compared to year end 2012, and our liquidity continues to be in excellent shape. We currently expect our debt to total book capitalization ratio at the end of 2013 to be approximately 34% to 36%.

Looking ahead to the forth quarter, the combination of another quarter of strong production and higher gas prices compared to last year points towards more records to be achieved by year end. In addition, we expect to provide our initial outlook for our 2014 capital program production and expenses in the early to mid December. That concludes my comments.

So we'll now turn it back to the operator who will explain the procedure for asking questions.

Thank you. We will now be conducting a question and answer session.

(Operator Instructions)

Thank you. The first question from Doug Leggate from the Bank of America Merrill Lynch. Please proceed with your question.

Thank you. Good morning, everybody. Steve, I'm not sure who wants to take this one. If I can try two, one on the Brown Dense and one on the Fayetteville. On the Brown Dense I understand clearly you're quite enthusiast about the potential new discovery you're calling it this morning. Can you give us some idea of scale, repeatability, location, or at least an idea of what's changed here for this latest vertical well that gives you greater confidence that this thing is going to work?

There's several things that go into it. Certainly how we're fracking, what we're seeing on the fracking side is giving a little encouragement. Really it just goes back to historically what we've found to date. If you go back to our third well that we drilled, that's the first well we drilled in the high pressure area. That well is continuing to produce fairly well. It looks like cash on cash we'll get our money back on that well.

The -- I think it was the fifth well that we drilled was called the Dean well. It's a vertical well. And again, it won't make much rate of return but it will make a little bit rate of return.

Then you've got this well that we just drilled. To put this well in perspective was what we think the production curve is going to be going forward. This well actually cost us $10 million to drill, it had some issues that we had on the drilling sides and we also had a lot of science. But at $10 million this well is still above our 1.3 PBI that's our economic hurdle.

The Hollis well, the well that we just finished and just put on production, had a little bit of troubles up hole with a zone getting through it. But it was basically a clean well. That well today after we've done all the fracs on it is less than $7 million. We think we can get that down to $6 million.

Well, a $6 million well with any rates anywhere near this is a high like 1.8 to 1.9 PBI, which is high, high 80%, 90% rate of return type numbers. And when you look at the map where those three wells are across the area, that covers well over a township. That's why I said early on that we're fairly comfortable in that general area of high pressure where we've got more of these to go after. We'll just work on the costs a little bit and the little bit we've learned on the fracking side.

Just to be clear, Steve, is this isolates it to the high pressure area? And what proportion of your acreage does that represent at this point, at least what you think is prospective?

We don't know if it's isolated high pressure area. Almost all the wells we've drilled recently have been in the high pressure. When I say almost all of them, the wells we're drilling right now, we internally call corner posts. The ninth well that we drilled is the farthest south and west step out that we've done. The 10th well is back on the Arkansas side of the border for what we're doing. The 11th is due north eight or nine miles. I can answer that question a lot better in another quarter or two quarters. But if you just take the high pressure area, we're looking at somewhere in the 150,000 plus acre range.

That's really helpful. I hate to labor the point but you're now thinking that this is a vertical program, not a horizontal program?

We don't know. In the Fayetteville early on, in the -- I think in the Eagle Ford early on, a lot of these other plays early on, they were vertical wells and then later went back to horizontal. Theoretically horizontal is ultimately out to be the right answer. But it's a lot cheaper to do it today with the verticals and we can learn faster doing verticals, so we will continue doing that for a while.

My follow up Steve is just a quick one on the Fayetteville. You've routinely given us an idea of what your economic backlog looks like at different gas prices, obviously it sounds like things have changed quite dramatically with this difference in your completion technique, the resting, and so on. I'm just wondering if you could help us, you've previously talked about 450, was a kind of bogey for stepping up spending. Could you just frame for us how your backlog changes with these better well results and when you might start to think about getting a little bit more -- putting more money back into the Fayetteville? I'll leave it there, thanks.

I don't know that we have a good answer on any changes to what I've talked about in the past as far as number of wells yet. The reason for that is that when you look at the upper Fayetteville for instance, the upper Fayetteville historically we just kind of lumped those together and said we have so much in place, it was such a recovery factor. Now that we've got an area -- and again, it's over 100,000 acres that doesn't look like it's communicated to the lower. You have to go back, relook at your gas in place across the whole field and make sure that you weren't conservative on that part.

Well, to the extent that you might be conservative there could be a lot of locations that go into it. We're at the early stages of understanding that. And then the completion techniques and the resting the wells and changes we've done in fracs with a little more sand, the best way I can characterise that is we're learning each individual part of the field how to do it better. And so the northern part of the field, putting more sand, a little less water seems to be working fairly good.

The resting, frankly, isn't worth the effort. Statistically if you look at it you get a little bit of extra early on, but it's just not worth it. Southern parts of the field, that water gave us a lot of trouble before. We weren't getting high enough initial rates to get us that first cash flow that we needed. There were a lot of wells that would be put in a marginal category. We're still trying to figure out how that works. The theme here is after 3,000 wells we're getting to the point where we're fine tuning the individual parts of the field and we're seeing good things as we do that.

Terrific. Congrats on a great quarter Steve, thanks.

The next question from Will Green from Stephens. Please proceed with you your questions.

Good morning, guys.

Good morning.

Steve, you've mentioned in your prepared remarks being a lot closer to knowing what it takes to make commercial oil in the Brown Dense. We went through the high pressure, obviously being one of them. Is there any other things that in hindsight look to be obvious characteristics of making this work beyond just kind of being in the high pressure zone?

Again, I need to caution you there. We're in the high pressure. I'm not sure that's a criteria you have to have to make it work. Certainly the higher the pressure, the higher the initial rates, those kinds of things. So you always want higher pressure. We just don't know enough about the whole area yet to know what works and doesn't work.

There's some things we're learning. Frankly, I don't want to discuss those right now. I think that gives us some competitive advantage maybe in some other plays. I'll just leave it there. We are learning some things.

Got you. You guys mentioned the thickness on the Sharp well was about 450 feet thick. How does that compare to previous tests you guys have done in the play, and how does that compare to the McMan and the Hollis?

In general the thickness is a little bit thinner to the north in Arkansas and then thickens as you go into Louisiana. Up by our first well, the Roberson well, if I remember right, that was a little under 400 feet, 350 feet or so. When you get to, say, the Hollis, Hollis is a little bit thicker, starts approaching 500 feet. But the interval's between 350 in the very shallow part of the area down to 500.

Great. I appreciate the color guys.

Our next question comes from the line of Gil Yang with DISCERN. Please proceed with your question.

Good morning everyone. Great quarter. Could you talk about the -- It looks like the Fayetteville is throwing out a fair amount of free cash. Can you talk about that and how you plan to allocate capital there going forward, and is the goal to maintain production flat there you think? Or with these new well results, do you think that that might be more growth there going forward?

We'll give our 2014 guidance here probably sometime in mid-December. But we've talked about in the past that we want to get the Fayetteville shale and we'd like to get the Marcellus as quickly as we can into cash flow positive cash flow arena, and then make decisions about what we want to do with that excess cash flow.

As you said, we are generating cash flow now. We will continue to generate it, I think into 2014. The real question we have now is I've got eight rigs running in the Fayetteville, do you add rigs, do you keep those eight rigs running, how do you do it in the 2014? We'll talk about that later in the year.

I don't think you'll see us significantly increase the rigs, by that I mean double the rigs or go four or five more rigs. But certainly we will tweak that a little bit. The back way to get into your question about holding production flat, it takes about seven rigs drilling with six day average wells to hold the production flat. So if all you're doing is eight to nine rigs it will grow, but it will grow at single digit numbers.

But that seven rigs is based on the historical well results, right?

Right. Right. And I don't have enough information to tell you what might happen if you had a little bit better wells.

Right. And can you just detail the specifics, as specific as you're willing to talk about with the completion changes that contributed to the better well results in the Fayetteville?

Yes, there were a couple of things that we did. First of all, in the areas where we -- that 10 million a well day for example, it's relatively deeper in the area. It's probably more like 5,200 feet in vertical depth. We had longer laterals, so we're at about 8,500 completed lateral length with 18 frac stages. We're trying to get more and more proppant in. We put about 7 million pounds of proppant in that well and 200,000 barrels of fluid.

The other side of this has been looking at how we flow them back. Certainly there's some is efficiencies in getting pressure reductions out by removing tubing streams and replacing them with some shorter laterals that can allow for well head pressure losses to be improved and improve friction pressure losses as well. And we've made some changes in how we flow back to the midstream Company in terms of the debottlenecking pressure constraints there as well. So the result of that led us to see quite a bit of improvement in the overall performance. We're testing that across the piece.

I think the 10 million a day well IP was very focused on trying to test productivity from that particular area. But we're seeing higher IPs across the space.

It was early on that it would be kind of boring on some of our responses on there --

Sorry.

Not that any means that Bill is boring. I think the thing is we've looked at the system wherever we're at and we look at every little point where there might be a bottleneck and we're trying to get rid of those bottlenecks plus give you something to it. We went specifically with a couple of these wells and said okay, do all the things you think you could to make it the best you can, and now you're seeing what that best you can is.

And how much of that well cost?

That -- the 10 million a day was $4.6 million including some science and some additional costs for the testing itself.

Great. Thanks very much for your help.

Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with you question.

Good morning and thanks for taking my question. Steve, you anticipated one of my questions in your prepared comments about fourth-quarter volumes. And looking at it, especially relative to the beat versus your guidance that you put up in 3Q for volumes, it looks like, there's just -- I look at it as 1.5% of sequential growth for Q4 versus about 6.6% for 3Q over 2Q. So it looks like that's going to be anomalously low quarter-over-quarter growth that you're guiding to. So am I looking at it the right way? Can you talk about some of the factors that may be a play there?

Well, there's kind of two things in general. In the Marcellus we won't have quite as many completions in the fourth quarter as we did in the third quarter. Frankly, the first quarter is going to have a lot more completions the way it looks. ¶ You say why is that happening? We are drilling on pad for the most part, and it depends on which pad comes up. If a couple of those pads move in earlier than we thought, you might see a bump in the fourth quarter. If they stay where they're at today, the first quarter gets to see that bump. The other thing is, Millennium has said they're going to have their pipeline down for eight days and we do have quite a bit of our capacity going down that Millennium line, and that's a scheduled maintenance. So when they do that, we factored that into our fourth-quarter guidance.

Got it. That's exactly the kind of color I was looking for. And then the -- the second thing if I could ask, the -- the upper Fayetteville, I think -- I believe I heard you say that you have 100,000 acres perspective for that. What I'm curious about is with two of those wells that came on over 6 million a day, I think my question is along the lines of, A, are those representative of what you think the upper Fayetteville can do? And B, if it is representative how much of that is reflective of a better reservoir and how much of it is reflective of better improved completion designs?

Again, I don't know that we want to go into a lot of details there. We think that we're learning some things that we can use in other places, and so I don't want to go into a lot of detail. But we've got now 30 -- roughly 30 wells in the upper Fayetteville. We've had some wells in the past that were very good wells, just not this good. We've got at least one well over 5 Bcf that we drilled a couple years ago.

We spent the last year, year and a half delineating the area. Just like I talked about earlier, now it's time to fine tune. And as we're fine tuning, we're getting better wells. Will all the wells in the 100,000 acres be that? No. But we're kind of learning the formula about the upper Fayetteville as well. Again, there's some things there in that formula we think we can apply in some other areas, so we will just kind of leave it at that.

Thank you for the color, Steve.

Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.

Thank you. Good morning. Going into the Marcellus, production looked very strong during the quarter, IPs which I think you highlighted in your opening comments, were down quarter on quarter. Sometimes it can be difficult to draw conclusions when we look at the chart that shows on one hand low IPs in the earlier days, but then performance that seems to be trending above you type curve.

So I wondered if you could add some color as to A, how the performance of recently drilled wells compares to past Marcellus wells, particularly those that are greater than 13 stages, B, the degree to which midstream related delays may impact the first couple hundred days of production, and then C, what you're seeing from wells drilled in Northeast Susquehanna County if you've reached critical mass there?

To address the IPs up front, you will know that in the range area, Susquehanna County where we're doing a lot of drilling and completing, we also have a series of compressor stations and midstream gathering that is required to get those wells online. In the quarter we were completing the compressor station to get another tranche of the wells. Now we have two-thirds of the wells that we have gathered in that Susquehanna County area in the range trust now on compression. So you will see those IPs as those pressures come down improve.

We've got solid performance, we're very confident that as we move through the delineation of the range area, wells are performing as we've expected. You get a bit of pressure difference between one end of the acreage to the other. All in all we've now got quite a bit of confidence to go ahead and raise our overall gathering capacity and get additional compression in and then move that forward. So midstream is really just building out infrastructure, not -- nothing to do with our long haul capacity, which is solidly locked up.

And -- and kind of a -- you didn't quite ask this question, but where are we comfortable, how do we feel about the wells and how much acreage is it that go into it. If you think about our Susquehanna total acreage, we've got about 130,000 acres. We're very comfortable that 60,000 of that acreage plus is as good as anything that anyone has got out there. I think Bill mentioned in his comments, going to what we call the north range, which is right along the New York border. We're heading in that direction and we're still getting very good wells.

Now, we do produce our wells a little different than some of the industry does. Bill mentioned some of the back pressure because of the compression. We don't have near the choke size that some others do. And so there's a lot of details that go into that. And part of that goes to your question about 30- and 60-day numbers. Some of our wells peak rates are actually past the 30-day mark because of some of those issues, and we want to be consistent and get 30-day numbers. Some of that is just how we're doing what we're doing out there.

Thanks. And then I guess in getting the new midstream capacity there, the gathering capacity, is there an implied EUR type curve improvement relative to your expectations?

I think there's partially the fact that we're seeing wells get unrisked, whether you call that better wells or not, we had risk wells before. Partially, it has to do with the new acreage, the Chesapeake acreage. We talked about that I think on our last conference call where our ultimate target is to get up to at least 1.2 Bcf a day. So it's a combination of both of those.

Thanks. And then Lastly, it looks like at least based on the cash flow statement you spent a little bit more than $1.6 billion in the first nine months. Can you just talk to the CapEx trajectory in the fourth quarter, and then any early thoughts on next year?

I think we've guided to $2.2 billion total and I think we're pretty much on that for the capital for the year. We'll have borrowed a little bit of money this year, and depending on what you want to use on the pricing next year and what you want to guess about capital next year, if you did $2.2 billion again next year and you're in a $4 price range, we're basically close to neutral on our cash flow.

Great. Thank you.

Thank you. Ladies and gentlemen, due to time constraints we ask that all questioners limit themselves to one question and one follow up. Our next question goes to Hsulin Peng with Robert W Baird. Please proceed with your question.

Good morning. So I was wondering if you can talk about your target well design in Marcellus? Just wanted to get a better understanding for the number of stages, levellings in your standard well, as well as well costs and also EUR expectations and whether that varies across the different parts in Marcellus.

We have an overall average on frac design for Greensweig at about 240 feet stage spacing. That means about 17 frac stages per well. We're inching that up a bit. We do have on right now 32 wells at 18 frac stages. But we're pretty comfortable that 240 in the Greensweig range, which represents Susquehanna and Bradford Counties makes sense. Probably over in the Lycoming area we think that you're more likely optimized around 500 foot staged spacing, and we're doing some tests to determine that.

I think our lateral length numbers are really probably more directed -- or influenced, sorry, by the shape of the units and the geography, as we do longer laterals in this area, we'll adjust spacing accordingly.

Our well costs are running about $6.4 million on an average CLAT well. We think that we've got some opportunities to improve on costs associated with those as we increase our activity and activity increases and there's more competition for services. We are seeing completion costs come down, partly due to the competition in the area and partly due to the fact that we have our own completion Company, which is helping us get additional competitive pricing in that arena as well.

The acreage varies. Just like we do in the Fayetteville we won't lock in on one average stage spacing or completion recipe. But we're being very targeted in how we go about that so we learn the most in the particular area.

Let me just add, it's a very similar story to the Fayetteville or to the Brown Dense. To the north, you're a little shallower a little lower pressure; to the south and as you go in this case, off to the southwest, you're deeper and higher pressure. The mix is going to be a little bit different from quarter to quarter and there are going to be different EURs. We're still trying to understand what those EURs are right now. I can tell you that in general for the wells that we current have on our books for the end of last year going into this year have an upward pressure on the ultimate recovery on those wells. We'll talk more about that when we talk about year-end numbers.

Okay. That was exactly what I was trying to get at in terms of the -- it seems like -- it sounds like there would be improvement in your EUR currently versus where you were at the end of 2012.

Yes.

And then I guess if I could ask my follow-up question, just in terms of the improvements in Fayetteville, I was wondering how much testing or production history do you need to see before you could revise your EUR assumption?

I think the answer to that is the same as almost any area. You've got two general issues. The quality of a well and then how big an area the quality of that well is over. And the quality of well takes several months of production to figure out the quality, and then you have to do it in other places to figure out how much of that it's going to be.

For instance, in the upper Fayetteville we have a lot of wells, we've been working on it for almost two years now, so we feel better about it when you think about the Marcellus or you think about the Brown Dense or something, we don't have near the wells and we're still learning a lot. Each one of them is going to be different on size and how fast you change your reserves.

I'll just remind everyone when you do reserves, SEC says you have to be 90% certain. There ought to always be an upward pressure on your reserves if you're doing it right.

Thank you.

Our next question comes from the line of Joe Allman with JPMorgan. Please proceed with you question.

Thank you. Good morning everybody.

Good morning.

Steve, back to the upper Fayetteville, could you just give us the implications in terms of number of possible locations or resource size given what you've done so far. I think you've said you drilled over 30 wells I think you said, and you've got over 100,000 acres. Talk about your plan too in terms of mixing up the lower Fayetteville with the upper Fayetteville drilling over the next year.

The upper Fayetteville is between 40% and 50% of the thickness of the lower Fayetteville. You're going to put it on wider spaces. We've talked about in the past that typical spacing for the lower Fayetteville, 60 acres, and some places may be a little tighter than that. This is going to be wider, this will be 80 to 100 acres spacing.

We will drill it just like any other plays where you've got an upper, lower, or however you've done it. Where, one, where they're on the pad we'll space out wells both in the lower and the upper at the same time. So it's just when you're in that part of the field. For the most part the acreage is on the northern part of our acreage block, and some of the areas where we've done a lot of drilling in the past. So as rigs move in there you will see us drill more. Each quarter it's going to swing a little bit.

Okay. That's helpful. And then back to the tables that you put in the press release, first with the Marcellus, if I look at that Marcellus table and I see in the third quarter you've drilled the wells with the longest lateral lengths, the highest costs, but the 30-day average rate is not as high, it's actually on the lower end of the prior quarters you list there.

Let me give you the easy answer right there. The mix changed a lot. The other quarters were all Bradford County, it's a little deeper and certainly higher pressure.

The pressure is what counts. We flowed -- this quarter we had a lot of wells in the range area. We're flowing the whole thing as Bill said before against 1,100 pounds pressure. Well 600 or 700 pounds difference in bottom hole pressure translates, if everything else is constant, to a lower rate. It doesn't mean the quality of reservoir is any different, doesn't mean anything more than now I've got a different differential between my service pressure and bottom hole pressure. And that's what you're really seeing what we're doing here.

On a per foot drilled, per stage shot, per perf cluster, we're very comfortable with what we've done so far in that range, northern Susquehanna area that it's -- it's every bit as good as what we're seeing in Bradford County.

Okay. So it would not be a right and correct interpretation if we were to say that what you're doing in Susquehanna county is going to be less productive than what you've done in Bradford county.

That would be a wrong interpretation.

Got you, okay. Moving over to that Fayetteville table, so you've got the longest laterals, the highest IP rates, and you've increased the 30 day and 60 day from the last two quarters, but the 30 day and 60 day are lower than a bunch of the other quarters. So what's the interpretation there?

In some of the cases -- there's two pieces to this and it's kind of like I said in the beginning, some of it's location, location, location. So the ways that work in the southern part of the field now, that is deeper. There are some places where you can do longer laterals there versus some of the shallow portions of the field. So you're getting a little longer lateral, but it's also different characteristics.

If you think about it, what Bill talked about on the rest of these wells, you didn't change your EUR at all. What you had was a low initial rate before that stayed low for a long period of time, and you still got the EUR ultimately. All we've done is figured out a way not to have the water come to the surface, which gave you the higher IP and you get the whole thing back faster. That's not really interrupting much in the 30 day rates, but as you get in the 60 day, 90, and 120 day rates, you start catching back up with that curve. The curve does change a little bit in shape, but it's really just a variance that you see going across there from various locations and the things we're trying to do in those locations.

But the EURs are not necessarily less lower going forward?

Not anything we're seeing.

Okay. All right. Very helpful. Thank you, guys.

Our next question comes from the line of Matt Portillo, Tudor, Pickering, and Holt. Please proceed with your question.

Good morning, guys. Just a couple quick questions on the Marcellus. Historically you guys have talked about running a four rig count to get to your growth expectations. With the incremental capacity you have today in combination with the improved well results, should we expect any material change in your rig count, or with the better wells versus your previous expectation, you may be able to still hit that higher capacity with the same amount of CapEx.

And then just a second question in regards to the take-away capacity, I was wondering if you could give us any color in terms of how much the incremental take-away capacity is going to cost on a transportation basis? And then finally, as you guys think about the overall Northeast market as pipes get connected into New York, I was wondering if you could comment a little bit about how you think about basis in the New York market in 2014 and 2015.

Okay. You had more than two questions or I forgot your first one. We'll start backwards and then we'll back to your first one. The whole basis as we look out into the future and then what do we pay for whatever we had in the newest announcement, the $150 million a day actually is going to be relatively cheap. We're paying about $0.10 for that. So that's one of our cheaper rates that we're paying on any of it.

If you think about all of our firm that we've got, the high side on it if we do back to back where you tie one liquid point and then tie to another liquid point, it could get as high as $0.50. But most of it is in that $0.20 to $0.25 range. This is the low side of that.

As far as what's going on in the Northeast, we've been talking about it for over a year now that as the Northeast fills, you basically have balanced the country and you're going to have a minus, and you'll long term with a minus to the current plus that you've had over the last couple of years. We think that minus is something $0.20 plus ultimately. Now over the short term it's going to be dynamic. I don't know that we can pick a point and say this point is going to be bad this day and this point is going to be bad another day. You can still move gas around just like the example I used where we bought from one and took it to another point and made some money. There's a lot of dynamics there you can move and fix points.

Certainly over the next year to year and a half there's going to be times where a point has got issues, and I think we should for the most part be in good shape where we can send to different points than whatever has the issue. That's been the goal for whatever we're doing as we go through. That's just kind of a general statement there. What was your very first?

The first part was on rigs in the --

On rigs. The best thing on rigs to say is just stay tuned. We're learning daily. The scenario you put together if you get better wells and you don't have any firm then yes, you can drill it with fewer rigs and go with it.

But we're looking for more firm. We're continuing to learn about our areas. And we already talked about starting the end of this quarter, we'll drill some wells in some new areas and start to learn from that. Expect in 2014 we're going to have a series of wells that won't get much production in 2014 because we'll just be learning about what we need to do and what size systems we need to put in in some of these new areas we have. So that's all going to play into whatever 2014 and 2015 look like. As I said, just stay tuned and we'll talk about that as we go through.

I would add one further comment. Just like our teams in the Fayetteville, the Marcellus team is doing a great job lowering the number of days to drill and becoming more and more efficient. So following rigs versus following well count, we're already seeing some rather dramatic reductions in time to drill.

Great. Thank you very much.

Our next question comes from the line of with Arun Jayaram with Credit Suisse.

Good morning, gentleman. I wanted to see if you could elaborate on the well cost. I know you talked about bringing 19 wells on in the Fayetteville, which have strong IPs in excess of 6 million a day. I just wanted to see what the average well costs or how many of those drills would have been drilled at your average $2.5 million range versus the higher well costs.

You mean the $4 million number that --

Exactly. Exactly. Just trying to parse out --

There were -- there were -- I don't know if there's another well that's $4 million. But there's maybe one or two at the $3.6 million range, $3.8 million range. But almost all of those were $2.5 million, $2.6 million, $2.4 million.

So the bulk of those are at the lower well costs.

That's right. We purposely did this test. As I said before, we did a number of things in terms of testing and extending the lateral lengths quite far and a number of things that added to that well cost.

If you think about the general increase in well cost this quarter, if your average lateral length goes up a couple hundred feet, we space our fracs about 300 feet apart, so you're getting 50% to two-thirds more frac stage per well. That's really the whole cost.

And Steve, as you talk about or think about looking at your Fayetteville EURs, generally, we've been running around the bulk of your inventory being spaced around 600 feet or just under 70 acres. Is that still a pretty good assumption?

That's fine.

Okay.

Each area is a little bit different but that's fine.

Okay, and then my follow up question was just looking at the midstream segment, obviously Devon announced a transaction with Crosstex, which was warmly received by Wall Street. I was just wondering Steve as you think about potentially financing the Fayetteville -- or pardon me the Brown Dense, where your head is at in terms of midstream.

Well, we will -- as far as financing Brown Dense, as we need the dollars we have a different ways to finance that. We haven't hardly used any of our borrowing base, we've got some other assets we can do some things with. So I wouldn't just assume that we're going to scale up, if and when we scale Browns Dense, that something is going to happen midstream.

Midstream we think about that as truly a very good asset. It generates a lot of money for us as we look at it. It makes a lot more sense today for it to be inside our Company than outside our Company. When you think about that LOE, when we talk about that some $0.80 of LOE, $0.60 of that is the midstream part in both areas, both Fayetteville and Marcellus. Actually a lit bit more in Marcellus.

And so having that internal, especially when I know some of the people are a little bit worried about gas prices going forward, and we need to be prepared if gas price goes down, it's a big difference if you set up (inaudible) and you've got $0.60 going cash out the door versus having internal to you. So we like where it's at today. And we will make decisions about what we want to do with the midstream in the future. But I wouldn't make the assumption that if the Brown Dense takes off and SWN needs capital, that we're just going to do something with the midstream. Or anything else for the sand company or anything else.

It sounds like it's a core part of the business that you plan to keep for the time being.

For the foreseeable future it's a core part of our business.

Thanks, guys. Appreciate it.

Our next question from the line of Amir Arif with Stifel. Please proceed with your question.

Thanks. Good morning, guys. Just initial question is on the 55 wells that you've done the resting period on, if you can just give us a sense of what the IP was on those 55 wells, and if you have a 30-day rate on any of those if you can provide that as well. And the follow-up question is on the Brown Dense, on the verticals I know you've only been through your maximum four stages, I'm curious that given the thickness what you think the potential is for number of stages on vertical.

I'll let Bill talk about Brown Dense and frac stages. But as far as the resting and what it was beforehand and what it is in the future and the 30-day rates, I don't have any of those numbers sitting in front of me. I can tell you that in general that the wells we drilled in the areas we're drilling now were 2 million type numbers. And we're probably in the high 2 millions, low 3 millions on the numbers that we have. So we've added 30% to 40% to the IP rates, but I don't have any other details.

And on the Brown Dense verticals when we planned a series of vertical wells we were looking at number of stages being somewhere between three and five. As we complete these wells, we began this process with the Sharp well, completing each particular stage separately, so that we can run some logs and try to determine whether we're getting frac height or not, which would dictate how many stages we needed.

We planned for four. And evidence in the completion told us that we were getting greater frac height than we had originally planned for so we backed it off to three. So we're using that sort of three to four frac stages as the planning and adjusting on the fly as we work through these.

Let me remind everyone, we're not even close to understanding how many frac stages we need or whether it's horizontal or vertical. So our best guess today may not be our best guess six months from now or three months from now or whatever that is.

Sounds great. Thank you.

Our next question comes from the line of Biju Perincheril with Jefferies. Please proceed with your question.

Hi. Good morning. So following up on that Brown Dense question, the number of stages that you're completing, the vertical thing, is that a function of simply the thickness of the formation or are you trying to access maybe different zones within the Brown Dense formation?

It's both. It's both. The eighth well, that's the good well, we for the first time fracked a very bottom part of the Brown Dense. And we announced then and we talked about that last quarter where we were getting a peak rate I think of about 170 barrels a day out of that. So in that case that fracs was set just for that zone. And then some of the fracs are just to get us across all intervals as well. That goes back to Bill's comment that each one we flow back separately, we did a lot of diagnostics on it. That's why it was a $10 million well, not a $6 million or $7 million well. So we're still learning those things but doing both.

So when you're drilling horizontally do you know if you're able to access all those different zones with one lateral, or is that the issue that you're having with the horizontal wells?

Well, certainly any of the horizontals we've done in the past we have not been able to frac across the entire interval. So as we go into the future that will be one of the things we have to figure out. I don't know -- I don't have an answer there whether we can or can't yet. Part of what we're trying to learn about the verticals is how to do it optimally so when we do try and do it horizontal, we get a shot at it.

Got it. And then my follow-up is the upper Fayetteville wells that you drilled, the 30 plus, are those in areas where you have existing wells in the lower Fayetteville?

Yes, we drilled the lower Fayettevilles throughout the entire year.

Got it. You're comfortable at this point that in all of that 120,000 or so acres you were talking about two separate reservoirs?

Yes. There is an upper and lower almost across the entire field, not quite the entire field. Some of it doesn't have much of a barrier. And we know we're getting upper and lower with what we're doing. This 120,000 we're very comfortable that we're getting almost no contribution from the upper.

Great. Thank you.

Our next question comes from the line of Bob Christensen with Canaccord Genuity. Please proceed with you question.

Yes. Thank you. Steve, on the Paradox basin, the first well, what depth were you taking that to? Because I saw a second permit, so my curiosity is up in the Paradox. Can you tell us a little bit about it?

We're mostly Cane Creek, I think that was just under 10,000 feet is where we landed our lateral. I believe it was about 9,600, 9,800 feet. I'll tell you on this, that well we're still doing the completion stages of it. But the first couple stages we've done on the completion have not given us the results we were hoping for. That does not give us any discouragement. This play is going to take some work to figure out if it's going to work or not.

We're certainly permitting some other wells, but there's several industry players around us that are drilling and permitting wells also. That's one of the reasons Bill didn't say much about it and I won't say much more about it. There are other zones other than the Crane Creek that are shallower and some of the permits you may see that are shallower than some of the other people out there and we'll be testing some of those zones in this well. So that's why he said stay tuned, wait a quarter so and we'll talk a lot more detail.

And then my follow up comes back to the Lower Smack. When do you think you might drill the next horizontal well? And the follow up on that is can you go back to two or three of your horizontals and refrac them and maybe learn by that?

Well, our seventh well is a horizontal. It has one or two stages in it right now. But it's ready as we learn from the verticals to go do some experimentation on. And really that can happen any time once we get to a point where we want to try that.

As far as drilling another horizontal, not in our immediate plans right now. As I said what we're trying to do now is do what we call corner post, what's going on towards the edge and work back towards the middle with some of the vertical wells that we're doing.

And then as far as reentering a well, we're looking at that. Probably not, maybe on one of them you could do something. But once you've fracked it there's -- trying to get science from it, fracking and then trying to learn from what you just did is very, very difficult. There are some mechanical issues all the time going back in a well. So we've got one well we can do some experiments on, and we will do those. And then future horizontal wells are down the road.

Thanks.

Our next question comes from the line of Ray Deacon with Brean Capital. Please proceed with your question.

Yes. Hey. Good morning. Thanks for taking my call. I'm just wondering, Steve, if you could expand a little bit on your response on the differential issue? Because it seemed as though you did much better than any of your competitors relative to NYMEX this quarter, and I was wondering if you could be a little bit more specific about how you had options to take gas to different pricing points I guess from the Marcellus?

We set up our system to -- I need to start with the two big lines that we can take gas to, is Tennessee Gas pipeline and Millennium line, that's where most -- that kind of brackets most of our acreage. So I'll start right off the bat and say if both of those have severe problems at some point in time then we're going to have some problems. I can't tell you we're never going to have a problem.

But we have enough flexibility that we can bounce between Millennium and Tennessee fairly easily. And that's because of our north/south ties between the Stagecoach line and that DT line, that's one of the reasons we waited so long to start developing. We needed to have a redundant and dynamic system before we wanted to get out there do it. And basically those lines, I think it's five or six different places you can sell on those lines by themselves, the Constitution line will come in 2015. Didn't help us this quarter, but that goes north, jumps over those lines and gets us to another point.

We can take gas today to the mid continent markets and take some of our gas to the southern markets. I won't go into a lot of details about that. But it's the same strategy we had in the Fayetteville shale. Where in the Fayetteville shale we can do anything east of the Mississippi and get gas to it. Our ultimate goal in the Marcellus is be able to do the exact same thing.

And the thought process isn't about this year or next year, we're going to be there for 20 or 30 years. I can't tell you even five years from now exactly where you need gas. I know you'll need it. I know the major population areas in the Marcellus, so I know it will always be priced better than the rest of the country. That doesn't mean you're not going to have some bumps along the way. Our purchasing is thinking down the road and trying to be prepared for anything that might come up down the road and it's worked well for us this quarter as we go through it.

Great. Thank you. Just one more quick one. Are you willing to talk about the breakdown of spending on new ventures, the $133 million between drilling and acreage 3D I guess?

This year I think it's just under $50 million. It's the land part of that. There's probably less than $10 million of science in it. And that number could change a little bit depending on what happens in New Brunswick, but it's basically in the $10 million range. The rest of that is drilling for 2016.

Got it, thank you.

Due to time constraints our final question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Thank you. Good morning, folks. Is there an asset in the new ventures portfolio that could rival the Brown Dense in resource potential and maybe value creation, whether it's the debt found in the Paradox basin or elsewhere?

That's one of those trick questions, Dan. We have got some acreage we haven't talked about. We would hope that we have acreage that would rival the Brown Dense in our portfolio. And certainly whenever we go into any of these plays we think about them as potentially being significant.

Now after you learn from them, I'll use the Bakken and Montana where we talked earlier about the fact that we were there and decided it just didn't quite make it to where we need it. There may be something in the Bakken and Montana but it doesn't have the scale after we did our first couple of tests there. It could happen, whether it's Colorado or Paradox or something we haven't talked about -- after you drill a couple wells, starts getting smaller and it gets too small for what you're doing.

But today the Colorado and Paradox both in our minds have the potential to be significant to our Company. Now, certainly the Brown Dense is 500,000 acres, Colorado is 300,000 acres, and we haven't talked about Paradox, but there's a little bit of scale in acreage. We still think they're significant and can be significant to the Company.

Understand. And then quickly as a follow up, on the Brown Dense, to confirm, your view, the play doesn't necessarily need to work on a horizontal basis for it to be declared a repeatable commercials success, correct?

Not at all. As a matter of fact, the three best wells drilled to date are vertical wells.

Right. Very good. Thank you.

Thank you.

Thank you. Mr. Mueller, I'd now like to turn the floor back over to you for closing comments.

Thank you. Over the years we've attended several investment conferences. I was asked recently by one of the new people to our story what makes you excited about Southwestern Energy. For any CEO that's a question we love to get and we're always excited to get it. I just wanted to end this with what makes me excited about Southwestern Energy.

First and foremost, it's our formula, the right people doing the right things, wisely investing in cash flow from [internal] assets, creating value plus. I think this quarter shows is value plus but the reason I started with the formula, it defines our culture. And that's the culture that Bill talked about before, about our relentless curiosity that leads to innovation, that leads to records that we saw in this quarter.

The other thing about that formula is it drives our values. You can't be successful without having the right kind of values. That's the number-one thing I'm excited about.

I'm certainly excited about the Marcellus, we've talked a lot about it today, the well results, the Northeast corner, we talked about our growing production. And we talked about the fact that what we've seen to date I think of our acreage matches with almost anyone else's acreage out there on a productivity per foot or on a productivity per lateral length or frac stage or however you want to do that.

I'm also excited, and we talked about it when we asked questions about the firm capacity we have. It took us a little longer to get started because we thought it was very important to have that firm capacity in place. We're continuing to add that firm capacity. We saw the benefits of it in the third quarter. I think we'll see some benefits of it in the near term, and I know we'll see some benefits of it in the long term as we go through.

And then I'm really excited in starting the fourth quarter. You will see as we start talking about 2014 you're going to see us move into some of the other counties on the new acquisitions that we had and you'll start seeing test in Wyoming, Sullivan, Tioga counties and we'll be able to talk about that starting early next year.

And then the Fayetteville shale, I'm excited. The fact that we keep learning to unlock more of the resource potential. That learning has allowed us to understand more about the Fayetteville shale. I'm excited about that.

And then I'm excited on exploration effort and the first thing that exploration effort obviously comes up is Brown Dense. I'll just remind everyone, Brown Dense is only part of our 1.3 million acres that we had in that last question. There's some good things I think can come out of that acreage as well. We'll continue to have that 1 million plus acres as we look on the future that we'll have as the upside to what we're doing.

And then I'm excited about the performance and the records we set. I'm very especially excited about the fact that a lot of our peers have given up on natural gas. And most importantly for us we haven't given up on natural gas, but we're actually and very easily able to deliver more value per dollar invested. And that's what makes value plus value plus.

And then finally I'm excited about the future. I think we have a transparent growth path in some great project areas. And the one key thing I want to leave you with is that we have got one of the few teams in the entire industry that understands what it takes to drill more than 3,000 wells, produce 3 Tcf of gas in nine years out of a single field. And I think that's going to do a lot for us in the future. I think what we're learning, as I said in some of the calls, has helped us setup for some of the things we're thinking about in the future, and I think that gives us an advantage. So with that, thank you for joining us today. We look forward to great fourth quarter. I wish you the best weekend possible.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.